IR 05000445/1998005
| ML20237C924 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 08/20/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20237C915 | List: |
| References | |
| 50-445-98-05, 50-445-98-5, 50-446-98-05, 50-446-98-5, NUDOCS 9808240249 | |
| Download: ML20237C924 (18) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-445 50-446 License Nos.:
NPF-87 NPF-89 Report No.:
50-445/98-05 50-446/98-05 Licensee:
TU Electric Facility:
Comanche Peak Steam Electric Station, Units 1 and 2 Location:
June 21 through August 1,1998 Inspector (s):
Anthony T. Gody, Jr., Senior Resident inspector Harry A. Freeman, Resident inspector
Paula A. Goldberg, RegionalInspector i
Approved By:
Joseph I. Tapia, Chief, Project Branch A Division of Reactor Projects J
Attachment:
Supplemental Information l
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gDR ADOCK 05000445 PDR
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EXECUTIVE SUMMARY Comanche Peak Steam Electric Station, Units 1 and 2 NRC Inspection Report 50-445/9805; 50-446/9d05 The resident inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection Operations Operations continued to be characterized by conservative plant operation. This was
demonstrated by the licensee's decision to reduce Unit 2 generation when main turbine blade vibration increased but was below the administrative limit (Section O1.2).
Operators continued to use self-verification and peer-checking as circumstances
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warranted and were attentive to the control boards. Operators demonstrated a clear knowledge of limitations and immediate actions, and demonstrated increased attention during increased main turbine blade vibration (Section 01.2).
Maintenance Plant material condition was particularly noteworthy. Equipment preservation was
effective. Little exterior corrosion was noted, even on systems exposed to severe service and outside weather conditions. Pump oilers were clean and always maintained full, motor air filters were exceptionally clean, mechanical pump seals leaked the prescribed amount, valve packing leaks were minimal, and valve packing followers were assembled with care to not impact valve stems (Section O2.1).
Maintenance activities were well conducted and in accordance with the work orders and i
instruction procedures. Technicians were knowledgeable, demonstrated ownership, and were conscientious to leave the work areas clehn. Quality assurance / quality control was observed during some of the maintenance activities as appropriate (Section M1.2).
Enoineerina I
i Engineering was proactive in developing and communicating conservative
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recommendations to support operating Unit 2 with increased main turbine blade vibration (Section 01.2).
Plant Support Security, Radiation Protection, and Chemistry, continued thir high level of performance.
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l Security personnel were knowledgeable, alert, and attentive to their posts, and (
responded appropriately to issues. The plant continued to be very clean radiologically,
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and was found to be appropriately surveyed and posted. Radiation work permit requirements known by workers. The Chemistry department continued to aggressively pursue and restore plant chemistry to very high standards (Sections R1.1 and S1.1).
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Report Details Summary of Plant Status
- Unit 1 remained at 100 percent power throughout the inspection period.
Unit 2 began this inspection period at 100 percent power. On July 16, the licensee conservatively reduced Unit 2 generation to 900 MWe (80 percent power) because of increased main turbine blade vibration. Unit 2 remained at 80 percent power throughout the remainder of the period.
l. Operations
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Conduct of Operations l
O1.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below. Through daily observations of control room activities, the inspectors concluded that both units were operated by knowledgeable operators using good self-verification techniques and communications.
01.2 Increased Main Turbine Blade Vibration (Unit 2)
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Inspection ScoDe (71707)
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On July'16,1998, the licensee conservatively reduced Unit 2 generation from approximately 1140 MWe to 900 MWe (100 to 80 percent reactor power) because of increased low pressure turbine blade vibration. The inspectors reviewed plant operating procedures and discussed plant limitations and precautions with operators, reviewed turbine vibration data, main condenser vacuum togs, and lake temperatures and discussed them with the system engineer, and discussed plant operation with management.
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Observations and Findinas Unit 2, Low Pressure Turbine 1, Blade 19 had been experiencing increased vibration with the slightly lower condenser vacuum resulting from high take temperatures. On July 15, Blade 19 vibration reached a peak amplitude of 6.7 millimeters (mm). At
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8.0 mm, plant operating procedures require operators to immediately reduce main turbine generation. At amplitudes greater than 9.0 mm, blade service life begins to
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decrease. The inspectors noted that operators were aware of the plant limitations, the immediate actions to be taken in the event vibration increased above prescribed limits, and that increased monitoring was appropriately implemented. The licensee's decision to reduce power before vibration reached the administrative operating limit was conservative and a review of plant logs and computer information revealed that the power reduction was conducted without any complications. During the power reduction, however, Blade 19. vibration temporarily increased to a maximum of 10.0 mm as had
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been predicted by engineers. Power was stabilized at 0630 on July 16, and Blade 19 vibration stabilized between 1.5 mm and 6.0 mm.
A non-contact turbine blade vibration monitoring system was installed by the licensee during the first Unit 2 refueling outage, because the Unit 2 main turbine experienced some minor main turbine blade cracking. The cracking occurred at a high stress location in the root of the turbine blade, and the licensee's failure analysis attributed the cracking to high cycle fatigue. During the last Unit 2 refueling outage, the licensee performed 100 percent eddy current testing and 100 percent magnetic particle testing of all L-0 (last row) low pressure turbine blades. This testing revealed five blades with similar cracking. ' nit 1 and 2 turbines were made by the Siemens Corporation.
Engineering involvement was both proactive and conservative. System engineers had periodically reviewed turbine blade vibration since the Unit 2 refueling outage, were
. aware o! the potential for a turbine blade vibration increase when lake temperature increased due to the summer heat, and anticipated the increased vibration with some innovative temporary modifications. For example, the increased vibration could have been the result ci iurbine casing displacement due to uneven heating or condenser vacuum changes. Temporary modifications to externally spray the turbine casing and to provide shade to the Unit 2 turbine were implemented. The modifications and continued
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engineering involvement demonstrated a proactive engineering organization focused on
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supporting plant operations, j
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Conclusions The licensee demonstrated conservative decision making when generator output was reduced after the Unit 2 main turbine blade vibration increased. As a result, no measurable decrease in the service life of the turbine blades occurred.
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Operators were knowledgeable of the operating limits of the main turbine and the immediate actions to be taken in the event turbine bla% vibration increased.
Operations management demonstrated conservative oderations when incre:: sed main turbine blade vibration monitoring was implemented and forethought in preparing crews for a downpower.
Engineering support to plant operations was evident in system engineer monitoring of the main turbine which resulted in proactive and innovative temporary modifications to reduce main turbine blade vibration.
Operational Status of Facilities and Equipment l
O2.1 Plant Tours ard Enaineered Safety Features Walkdowns The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following engineered safety features systems:
Unit 1 Train A emergency diesel generator
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Unit 2, Train B eraergency diesel generator j
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Unit 2, Train A and B Juxiliary feedwater pumps
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l Units 1 arid 2, control room f
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Unit 2 feedwater
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Unit 1 and 2 service water
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i Equipment operability, material condition, and housekeeping were acceptable in all cases. Plant material condition was particularly noteworthy. Equipment preservation was effective. Little exterior corrosion was noted, even on systen.s exposed to severe service and outside weather conditions. Pump oilers were clean and always maintained full, motor air filters were exceptionally clean, mechanical pump seals leaked the prescribed amount, valve packing leaks were minimal, and valve packing followers were assembled with care to not impact valve stems. The inspector concluded that these observations demonstrated effective maintenance. One isolated exception was the condition of the service water pump building where dust, spider webs, dead bugs, and spiders clearly affected the ability to maintain good housekeeping and in at least one case resulted in dirty service water pump motor air filters. The licensee indicated that I
the service water pump building is typically very difficult to maintain because of its location and propensity to breed insects. Service water pump air filters were not sufficiently clogged to affect motor operability. Several other minor discrepancies were.
brought to the licensee's attention and were all corrected satisfactorily. The inspector identified no substantive concems as a result of these walkdowns.
II. Maintenance M1 Conduct of Maintenance M1.2 Maintenance and Surveillance Observations a.
Inspection Scope (61726. 62707)
The inspectors reviewed and/or observed the conduct of both plant surveillance and maintenance during the report period. The inspectors observed all or portions of the following activities:
Unit 2, Train A digital high range area monitor (P.RE6292) channel calibration
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Unit 2, Train B emergency diesel generator operability test
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Unit 1, Train B containment spray pump and valve operability test
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Unit 2, Train A digital high range area monitor (2RE6292) channel calibration
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Unit 1. Train A emergency diesel generator heat sensitt e tape replacement
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Unit 1, Train A emergency diesel generator emergency start /run mode
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calibration Unit 1, Train A emergency d:esel generato operability test
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Unit 2, Train A auxiliary feedwater pump 2-01 speed probe / tachometer j
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troubleshooting / repair Unit 2, Train A auxiliary feedwater pump trip and throttle valve major inspection
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Unit 2, Train A auxiliary feedwater pump regulator replacement J
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Unit 2, Train A auxiliary feedwater pump operability test
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Observations and Findinas The inspectors observed that the work performed during the above activities was conducted in a deliberate and controlled manner. :hese observations were consistent with observations made in previous inspection reports. Pre-work briefings were timely and thorough. Excellent three-way communications were observed throughout the performance of the work. Individual work groups reviewed the work steps and discussed the potential consequences and appropriate responses. Operators and technicians performing the work read the steps aloud before performing them and demonstrated good self-verification. The inspector noted that both operators and maintenance technicians ensured the procedures being used were acceptable prior to their use and demonstrated ownership by correcting even minor procedure problems.
The plant equipment operator identified a small fuel oil leak during the Unit 2, Train B emergency diesel generator operability test and appropriately communicated it to the control room. Control room operators contacted the PROMPT team (a 24-hour service prompt maintenance support organization) who repaired the leak. The inspector
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observed this leak and noted that the leak was very small and that the plant equipment i
operator had to be quite observant to even identify it, c.
Conclusions
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Maintenance activities were well conducted and in accordance with the work ordesu and instruction procedures. Technicians were knowledgeable, demonstrated ownership, and were conscientious in leaving the work areas clean. Quality assurance / quality control was observed during some of the maintenance activities as appropriate.
M8 Miscellaneous M&tenance issues I
M8.1 (Closed) Unresolved Item 50-445/9802-03: inadvertent removal of wrong source range detector. In NRC inspection Report 50-445(446)/9802 the inspectors documented that, i
with Unit 1 in Mode 4 on March 21,1998, technicians were replacing the Train B source j
range nuclear instrument detector and inadvertently racked out the Train A source range I
detector while the Train B source range instrutnent was out of service. This resulted in both trains of sourco range nuclear instrumentation being out of service for approximately 4 minutes. Tecnnical Specification 3.3.1, " Reactor Trip System I
instrumentation," requires that two channels of source range nuclear instruments be l
operable while in Modes 3,4, or 5. With one less than the minimum required channels, Technical Specifications require that the inoperable channel be restored within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
With no channels operable, a source range instrument must be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
At the expiration of the allocated time limits, the Technical Specifications direct that the reactor trip breakers be opened and that all operations involving positive reactivity changes be suspended. The inspector reviewed the operator's response and concluded I
that the Technical Specification limiting coriitions for operation were satisfied.
r Technical Specification 6.8.1 requires that written procedures be established, implemented, and maintained as recommended by Appendix A of Regulator /
Guide 1.33, Revision 2. Regulatory Guide 1.33, Revision 2, Section 9 specifies that m
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-7-procedures be developed for planning and performing maintenance that can affect the performance of safety-related equipment. Contrary to the above, the licensee failed to properly implement maintenance procedures governing the replacement of the Unit 1, Train B source range nuclear detector.
The licensee's immediate corrective actions included restoring the Train A source range nuclear instrument to service, writing a Operations, Notification, and Evaluation (ONE)
Form, and counseling the technicians. The ONE Form was classified as a plant incident and a performance enhancement review committee meeting was appropriately held.
This non-repetitive, licensee-identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-445/9805-01).
Ill. Enaineerina E8 Miscellaneous Engineering issues E8.1 (Closed) Insoection Followuo item 50-445/9601-03: monitoring the licensee's erforts to identify service water system leakage.
The inspectors reviewed ONE Form 95-913, dated September 20,1995, which documented this potential adverse condition. The inspector noted that the licensee installed wells to determine whether the ground water that flowed along the service water intake structure was originating from the service water discharge canal or from a source further west of the canal via the pipe trench. These tests confirmed that the movement of ground water was in two opposing directions and provided further evidence that the discharge canal provided some of the ground water flow. The licensee also noted in the ONE Form that the water entering the storm drain piping and the water flowing to the service water intake structure seepage remained clear and showed no signs of sediment transport.
The licensee performed walkdowns of the north shoreline of the safe shutdown impoundment and service water discharge canal to determine if other seepage areas existed and to ascertain the mechanisms for service water to enter the shallow ground water and ultimately to the seepage areas. No additional seepage areas were discovered. The licensee inspected the concrete apron of the service water seal well and noted minor settling of approximately one inch of the apron downstream of a construction joint. A pit on the north end of the construction joint was excavated to assess the condition of ine six inch PVC water stop that was installed on this joint. The licensee noted that this water stop was severed. The licensee concluded that this provided a convenient path for the service water to exit the canal and flow to the pipe trench that served as a conduit for the seepage flow. The licensee concludea that the
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seepages were originating from the service water discharp canal and the service water
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piping. The licensee stated that repairing the construction pint would reduce the i
seepage flows. However,it would not eliminate the ground water flow. Since natural l
ground water was considered a major part of the flow, the licensee believed that repairing the construction joint was not necessary.
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-8-i The inspector noted that the ground water flow path could not affect any safety related p!l ing with the exception of where it crossed both trains of the Units 1 and 2 inlet service water piping. The licensee indicated that during construction, trenches were carved in rock and that the service water piping was placed in these trenches along with safety related grade sand. The sand was compacted to specifications.
The inspectors reviewed the licensee's Performance Monitoring Equipment List which contained equipment that was periodically monitored. The licensee included the service water discharge canal to the ultimate heat sink flow path in the list and every six months monitored the seepage sediment at the service water intake structure discharge point, the seepage sediment at the parking lot to the storm drain, monitored the construction joint and the ground in the vicinity of the joint, and monitored for sink holes and evidence
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of unstable soil conditions in the vicinity of the joint. In 1995, the leakage at the service
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water intake structure was 40 gpm and the leakage at the storm drain was 29 gpm. The license monitored the leakage to both areas while performing the surveillance and noted that die leakage at the intake structure was 4.2 gpm and leakage at the storm drain was 7.6 gpm in Octobe 1997. In April 1998, the leakage at the intake structure was 2.1 gpm and leakage at the storm drain was less than 2 gpm. The licensee attributed the decreasa in leakage to the dry weather conditions and concluded that the leakage in 1995 was due mainly to ground water, not service water leakage. In addition, during the surveillance, the licensee did not see any sediment around the intake structure or the storm drain seepage points. There was no change in the construction joint and no indication of unstable conditions.
The inspector concluded that the service water pipe integrity was not affected. This conclusion was based on the fact that ground water flow velocity rates were sufficiently low to not transport or adversely affect pipe backfdl, because of the large cross-sectional area of the service water pipe trenches and the low ground water flow rates. This conclusion was supported by the fact that no sediment transport or dissolved limestone was observed in the seepage and because no changes in site grading were observed.
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i E8.2 (Closed) Violation 50-445(446)/9712-01: five examples of a 10 CFR Part 50, j
Appendix B, Criterion XVI corrective action violation.
Backaround in NRC inspection Report 50-445(446)/97-12, the NRC identified five examples of a 10 CFR Part 50, Appendix B, Criterion XVI, corrective action violation. The issues were as follows:
i On May 14,1996, the Unit 2 safety injection system Train A Relief
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Valve 2-8853A was found leaking and was subsequently replaced. However, a ONE form was not initiated to evaluate the occurrence. The licensee replaced the relief valve using a work order.
In March 1996, the diaphragm for the reactor Makeup Water Pump Discharge
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Valve 2DD-0019 failed and was replaced under Work Request 3-95 322110.
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Between July 6,1994 and Mai 6,1996, the licensee identified seven instances
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where diaphragm valves had fa/ed or were in danger of failing because an internal finger plate was installed upside down. However, the licensee did not j
take action to identify the location of each potentially improperly installed j
diaphragm valve, and either inspect the valves or evaluate the adequacy of the j
installed configuration.
Within Plant incident Report 96-055, the licensee identified a significant condition
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adverse to quality involving numerous failures to properly assess a slow closure condition of Feedwater Isolation Valve 1-HV-2315. However, the licensee failed to determine the cause of this condition and failed to take corrective actions to preclude repetition.
t In March 1997, information was received from the motor-operated valve analysis i
and test vendor by Technical Notice MUNT 96-02 that previously provided error information related to the 3500 diagnostic system strain modules was non-conservative. However, the licensee did not initiate a ONE form to evaluate
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the occurrence.
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Inspection Followuo
The inspectors reviewed Letter TXX-97143, dated July 10,1997, which provided the licensee's response to the violations ir RC Inspection Report 50-445(446)/97-12. The licensee stated that the conditions idesfied in the violations were corrected so no immediate corrective actions were warranted. In addition, operations, engineering and maintenance management had reemphasized the importance of ONE form initiation in accordance with the applicable procedures. The licensee stated that management's expectation with respect to ONE form initiation threshold was reemphasized periodically.
In a letter to the licensee dated September 4,1997, the NRC concluded that the licensee's July 10,1997, response to examples 1,2, and 5 of the violation were responsive to the concerns raised in the violation but also equested additional information for examples 3 and 4 of the violation. The licensee's additional response letter dated October 3,1997, stated that a ONE form was initiated to document the review performed for generic implications of the finger plate issue described in creple 3 of the violation. The inspectors reviewed this ONE Form (ONE 97-435)
dated May 2,1997, and found that the licensee's corrective actions verified that no valves that had their diaphragm's replaced and were required to fully open to perform a safety function had incorrectly installed finger plates. The inspector concluded that the licensee's corrective actions were sufficient to prevent a diaphragm failure from adversely affecting a safety function.
. In the same letter to the licensee dated September 4,1997, the NRC stated that, for
I example 4 of the violation, the corrective actions stated in Licensee Event Report 96-02 addressing the metal fragment problem in the main feedwater isolation valve were adequate. However, the NRC also considered that the response did not provide details regarding the reasons that corrective actions were not developed for previous slow
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The licensee's response to this issue provided in their October 3,1997, letter, indicated that the previous closures of the feedwater isolation valve were documented on either a
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ONE form or work request. The licensee's engineers evaluated these events and dispositioned them as limit switch problems. The limit switches were replaced or reworked and the valves were returned to operable status. The licensee stated that the slow closure of the feedwater isolation valves was not discovered before the January 1996 plant trip because: (1) before the January 1996 trip, there was no
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l guidance for the plant operators to check the closure time of the valves after a plant trip; (2) the last reguir scheduled time response tests showed proper closure time; and (3) the feedwater regulating valves functioned properly and masked the slow closure of the feedwater isolation valves. The licensee stated that the problem was identified
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during the January 1996 trip because the failure that caused the trip 3 hut the feedwater isolation valves, but did not shut the feedwater regulating valves. As a result, a review of plant computer printouts showed that feedwater flow existed longer than expected.
After the trip, the licensee replaced all four of the solenoid valves on the feedwater j
isolation valves to prevent recurrence. The inspectors reviewed Plant incident j
Report 96-055, dated January 26,1996, which documented the plant trip and slow closure of the feedwater isolation valve. The inspectors verified that the solenoid valves were replaced and stroke tested. The inspectors determined that the licensee had taken adequate corrective actions.
In addition, the inspectors reviewed the Nuclear Overview Department Evaluation l
Report NOE-EVAL-97-000111, dated February 12,1998, whien evaluated 65 ONE l
forms. The inspectors noted that the eva!uation found that the threshold for initiation
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was acceptable. Many of the conditions reported were minor, documenting administrative concerns which indicated that the originators were conservative in their reporting philosophy.
Tiie inspectors also reviewed highlights from the July 13,1998, plan of the day meeting where one of the items discussed was the ongoing ONE form contest. The inspectors noted that the purpose of the contest was to increase awareness of the ONE form process. The licensee was hanging posters around the site that stated "When In Doubt, Fill ONE OutL" The poster featured a picture of a blank ONE form.
The inspectors determined that the licensee's corrective actions were adequate.
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E8.3 (Closed) Violation 50-445/9712-02: failure to contain reference to previous similar events in Licensee Event Report (LER) 50-445/96-02.
Backoround in NRC Inspection Report 50-445(446)/97-12, the NRC reviewed LER 50-445/96-02 as part of a review of a feedwater isolation valve slow closure event. The NRC questioned the adequacy of the LER in that it did not reference prev'ous similar events. In the event, Feedwater Isolation Valve 1-HV-2135 stroked closed in greater than the five
' second limit imposed by Technical Specifications. At the time that the LER was issued, the licensee was aware of other occurrences where the same valve had stroked closed
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-11-in greater than the limit imposed by the Technical Specifications. However, the licensee provided the following statement in the LER:
"There have also been similar events related to slow closure of main feedwater isolation valve on Unit 2.. However, corrective actions taken to resolve the causes of the previous events would not have prevented this event" Although the reference to Unit 2 valves was of uncertain origin, the licensee was able to find an instance in 1995 when Valve 2-HV-2137 stroked closed in 5.91 seconds instead of within the 5.0 second Technical Specification r6 quired stroke time. The previous events of slow closure of Valve 1-HV-2135 were not discussed in any other section of the LER.
The LER stated that a metal fragment in a hydraulic solenoid valve was the probable
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cause of the failure and concluded that since the valve was installed in 1993, that the
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fragment could not have entered the valve during service, and that the valve was conservatively considered inoperable from the time of installation until the solenoid was replaced in January 1996. This statement, along with lack of mention of slow closures of the main feedwater isolation valve, left an impression that the slow closure mentioned in the LER was the only known occurrence of this event. The NRC concluded that there was a failure to report previous occurrences of failure of Valve 1-HV-2135.
Insoection Followuo The inspectors reviewed the licensee's response to the violation dated July 10,1997.
The licensee considereo that NUREG-1022, Supplement 1, stated that previous occurrences should include previous events or conditions which involved the same underlying concern or reason why the LER was being written, such as the same root cause, or the same failure, or the same sequence of events. The licensee stated that the main feedwater isolation valve may have been inoperable for a period of time that exceeded the Technical Specification allowed outage time. However, no conclusion was reached during the root cause analysis that the main feedwater isolation valve was inoperable. The licensee further considered that there were no previous reportable events that had the same root causes, or the same failure, or the same sequence of events reported via LERs. The section of the LER which detailed similar events stated that there had been previous similar events with respect to slow closure of tM main feedwater isolation valve due to a known indication problem. The licensee stated that the corrective actions taken to resolve the causes of the previous events would not have prevented the event reported in LER 50-445/96-02. Therefore, the causes, failures or sequences of events were different from those reported in the LER. The licensee concluded that the corrective actions for the previous slow closure events would not have prevented the slow closure event caused by a metal fragment restricting the flow j
through the solenoid which was reported in LER 50-445/96-02. The licensee further concluded that the previous slow closure of the main feedwater isolation valse had not been properly defined ar,d could be misleading. The licensee stated that corrective actions consisted of initiating a ONE form and issuing a supplement to the LER. The inspectors reviewed the NRC response to the licensee's July 10,1997, letter dated i
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-12-September 4,1997, and noted that the NRC considered the licensee's letter responsive to the concerns.
The inspectors reviewed LER 50-445/96-02, Revision 1, dated July 10,1997, which the licensee ist aed to clarify Revision 0. The inspectors noted that Section VI, titled
" Previous Similar Events," was rewritten as follows to clarify Revision 0 of the LER:
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"There have also been previous events related to slow closure of main feedwater isolation valve on both units. However, the previous slow closures of the valves were reviewed during the disposition of this event: and no previous events that had the same root cause, or the same failure, or the same sequence of events were found."
The inspectors determined that the licensee's corrective actions were adequate and noted that the corrective actions agreed with the corrective actions listed in the licensee's July 10,1997, letter.
EB.4 (Closed) Violation 50-445(446)/9712-05: inadequate installation of temporary lead shielding.
The inspectors reviewed ONE Form 97-429, which was written to address the inspectors
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concerns, and discussed the issue with appropriate licensee personnel. Corrective actions for the ONE form appropriately clarified the use of tie wraps in seismic Category I buildings to ensure proper installation of lead shielding blankets around piping and for hanging lead shield curtains from plant structures. The licensee determined that commercially available stainless steel tie wraps with a minimum of 250 pounds tensile strength would be used for wrapping lead shielding blankets around pipe.
The licensee further clarified how many tie wraps should be used for different weight blankets. The inspectors review of Procedure RPI-608," Control of Temporary Shielding," Revision 6, dated July 30,1997, revealed that Attachment 2 of the procedure was appropriately re vised to specify that stainless steel tie wraps would be used to i
secure lead blanket 1. In addition, the procedure specified the number of tie wraps to be i
used for specific wr.ight lead blankets. The inspectors reviewed Calculation Change Notice 2 for CalcMation ECE-PSE-139, Revision 0, and found that it appropriately incorporated t% evaluation of tie wraps.
The licensee walked down the eight temporary shield;ng installations in the plant and supplemented all of the plastic tie wraps holding lead blankets with stainless steel i
strap.s. The inspectors walked down some of the installations and verified that stainless
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steel tie wraps were installed. The inspectors concluaed that the licensee's corrective actions were adeqt:ste to prevent recurrence of trie volation.
E8.5 (Closed) Inspec+ ion Followuo item 50-445(446)/9712-03: shelf life of actuator diaphragms.
The inspectors reviewed the corrective actions for ONE Form 97-409, which the licensec initiated to evaluate the shelf life of actuator diaphragms. The licensee
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inspected all of the actuator diaphragms in the warehouse for cracks, nicks, and dents
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l-13-I and discarded a number of them. Warehouse inventory was reviewed and a shelf life expiration date of October 15,1997, was assigned. New stock was ordered to replace the stock that expired. The inspectors reviewed the purchase orders for the new diaphragms.
l The licensee contacted Fisher Controls, the manufacturer of the actuator, and found that Fisher recommended a shelf life of two years for the diaphragms which could be extended to 6-years if special storage conditions were met. Two of these conditions were packaging the diaphragms in light proof bags and excluding flowing air to the parts. In addition, the licensee contacted RPP Corporation, the manufacturer of the nitrile diaphragms, who stated that, based on past history, a seven year shelf life was conservative.
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The inspectors reviewed Pre-Engineered item Data Sheet Number NEM0993, dated i
June 6,1997, which the licensee revised for the procurement of Fisher Controls elastomeric parts. The inspectors noted that the licensee required that all diaphragms should be individually packaged in ultraviolet resistant bags as a minimum. In addition, the licensee revised Warehouse Procedures MMO 4.03, "!ssues and Returns,"
Revision 7, MMO 4.02," Handling and Storage," Revision 5, and MMO 4.01, " Receiving i
and Examination of Materials, Parts, and Components," Revision 8. The inspectors I
reviewed the procedures and noted that the three procedures specified that actuator diaphragms should be packaged separately in ultraviolet resistant packages. The
inspectors determined that the licensee's corrective actions were sufficient to resolve j
the actuator diaphragm shelf life issues.
l E8.6 (Closed) LER 50-445/97001-00: identified single failure outside of design basis. On i
January 24,1997, after reviewing a similar condition reported by another nuclear power I
plant, the licensee concluded that a valid scenario existed which had not been previously evaluated. The event consisted of a feed line break occurring on a steam generator fed by the Train A motor-driven auxiliary feedwater (AFW) pump coincident with the single failure of the Train B solid state protection system (SSPS). Because of the SSPS failure, the Train B motor-driven AFW pump fails to start and the Train B
l steam supply valve to the turbine-driven AFW pump fails to open. Because the Train A motor-driven AFW pump delivers its hw to the feed line break and the turbine-driven AFW pump steam supply is from the depressurizing steam generator, an adequate supply of AFW could not be assured.
The licensee developed and implemented a design modification to restore the original design basi' )f the plant. The modification swapped the controls and indications to the
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two steam supply valves to the turbine-driven AFW pump. Following implementation, l
the Train A SSPS would actuate the steam supply valve from a steam generator fed
from the Train B motor-driven AFW pump, while Train B SSPS would actuate the steam
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supply valve from a steam generator fed from a Train A motor-driven AFW pump. In
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feed line break is on another generator. The inspector verified that this design
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I modification had been implemented during the last outago in both units.
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-14-Tae inspector concluded that the identification of the condition indicated that the licensee continued to effectively use industry information. The resolution of the problem and restoration of the original design basis was timely and copropriate.
E8.7 (Closad) Followuo item 50-445M46)/9616-04: loose fuse clips. This item was left open to review the adequacy of corrective actions to the fuse control program associated with an inadvertent start of an auxiliary feedwater pump on November 30,1996. Electrical contact degradation between the fuse and the clip caused a loss of control power to one of the steam admission valves which allowed it to open.
The inspector reviewed the status of corrective actions. The licensee had determined that there were 27 Buchanan, Model 361, fuse clips in each unit which could have an operational impact to the plant. Contact degradation could cause inadvertent actuation of safety related equipment or could cause a plant transient. Licensee investigation revealed that after the fuse had been removed from the clip 50 times, the force necessary to remove the fuse dropped by approximately 9 percent. After 100 times, the force dropped by approximately 32 percent. After squeezing the clips, the force necessary to reniove the fuse was approximately the same as the first time. Tne licensee developed a design change to replace those with a different type of clip.
The inspector found that the licensee had replaced all but four of the 27 clips in Unit 1,
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but still had not implemented these changes in Unit 2. According to the licensee, the design change has to be installed during an outage. Since the scope had not been finalized until September 1997, design change implementation was not scheduled in the most recent outages. However, most of the clips were replaced during the Unit 1 Spring 1998 refueling outage as opportunities and manpower allowed. The licensee intends to complete these changes during the next extended outaces in both units. The next outages are schedeled to occur duri.sg the Spring and Fall 1999 for Unit 2 and Unit 1 respectively.
The inspector reviewed whether any of the 27 clips could cause a f ailure of safety-related equipment without indications. The inspector found that only the fuses for the non 1E load 480 volt shunt trip coils could potentially fail without identification and without backup. The other fuses had either control board indication or annunciatic,n, failed in the safe condition, was in line with another train which had indication, or l
affected equipment which was only used briefly during startup. The licensee considered i
that the quarterly surveillance tests on the equipment was sufficient to ensure operability, Based on the lack of failure history of these fuse clips, the inspector agreed with this conclusion.
The licensee developed intern corrective actions to ensure that the fuses were consistently installed in a manner which reduced the likelihood of fuse clip failures. The inspector questioned several plant equipmer't operators on the proper method of fuse installation. Each was familiar with the rnethod for fuse installation but had different I
understandings of which cabinets contained clips that still were required to be squeezed.
Each operator stated that they would refer to the standing order prior to installing any
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fuse. The inspector found that the differences in understanding occurred because the licensee had provided amplifying guidance to the standing order by using an operation's'
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.6 e-15-shift order, but that this gtClance was in the shift order only for a few days. Operators not on watch during that shift were not familiar with tne amplifying information.
Conclusions The inspector concluded that the licensee's corrective actions were thorough and that the decision to replace the Buchanan, Model 361 fuse clips with Bussman clips was appropriate. The Bussman clips were constructed out of an alloy which was approximately 90 percent copper. The licensee concluded that the higher alloy content of the Bussman clips would reduce the amount of relaxation during installation and removal of the fuses. Testing revealed that while there was some reduction over time, the force necessary to remove the fuse from the Bussman clip after 1000 cycles was still greater than the force on the Buchanan clip on the initial removal. The inspector concluded that the licensee had thoroughly researched the replacement clip.
The licensee reviewed the use of the Buchanan 361 fuse clips and developed an operation's standing order providing guidance to operators when reinstalling fuses in cabinets containing these clips. Additionally, the licensee periodically performed thermography to identify degradation of electrical contacts between clips and fuses.
The inspector concluded that these were appropriate interim actions to prevens loose fuse clip problems until the clips could be replaced with Bussman clips.
The inspector reviewed the state of the licenses's corrective actions. The iicensee reviewed the list of components affected by the Buchanan fuse clips and concluotd that there were 27 clips which had an operational impact on the plant including inadvertent actuatien of safety-related equipment or causing a plant transient.
IV. Plent Support R1 Radiological Protection and Chemistry Controls R1.1 General Comments (71750)
Radiological protection personnel maintained appropriate controls over high radiation areas and plant areas toured were properly posted. Maintenance and surveillance activities observed within radiologically controlled areas were found to be conducted in accordance with the appropriate radiation worker ptactices. The inspector-s verified that effluent and environmental radiation monitors and meteorological tower indications remained operable and that appropriate compensatory actions were taken for those which were out of service. The inspectors routinely reviewed secondary water activity analyses and primary plant chemistry analyses and verified that these parameters remained within Technical Specifications and procedural limits, and that appropriate actions were being taken for those suhich did not.
During observations of a number of maintenance activities described in Section M1.1 above, the inspectors questioned personnel on the requirements of the general access permits (GAPS) for the jobs they were performing. Radiation workers were found to be familiar with their GAP requirements. In addition, the licensee was observed to be t
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-16-conducting extensive surveys on radiation worker GAP knowledge. The inspector considered the practice of conducting surveys of this type to be proactive.
S1 Conduct of Security and Safeguards Activities S1.1 General Comments (71750)
Inspection of the licensee's security program during the inspection period included a
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verification of the integrity of selected protected area barriers, maintenance of isolation zones, and protected area personnel access measures. The inspectors found the security personnel to be knowledgeable of their assigned stations. Security officers touring the plant were attentive and of en identified issues to plant management.
Material condition of security equiprv tit continued to be excellent.
V. Manar.ement Meetings X1 Exit Meeting Summary -
The inspectors presented the results of the inspection to members of licensee management on August 6,1998. The licensee acknowledged the findings presented.
The inspectors acknowledged these comments. No proprietary information was identified.
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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee C. L. Terry, Senior Vice President and Principal Nuclear Officer M. R. Blevins, Vice President, Nuclear Operations J.J. Kelly, Vice President, Nuclear Engineering and Support R.D. Bird, Jr., Plant Support Manager S. Sawa, Outage Manager D.L. Davis, Nuclear Overview Manager M. L. Lucas, Maintenance Manager D.E. Buschbaum, Technical Compliance Manager D.J. Depierro, Smart Team #3 Systems Supervisor INSPECTION PROCEDURES USED IP 61726:
Surveillance Observations IP 62707:
Maintenance Observations IP 71707:
Plant Operations IP 71750:
Plant Support Activities IP 92700:
Onsite Followup of Written Reports of Non-routine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance l
lP 92903:
Followup - Engineering j
ITEMS OPENED. CLOSED, AND DISCUSSED l
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i 50-445/9805-01 NCV inadvertent removal of source range detector during maintenance, j
Closed l
50-445/0601-03 IFl Monitoring the licensee's efforts to identify the exact source of the service water leakage.
!60-445(446)/9616-04 IFl Loose fuse clips.
50-445/97001-00 LER Identified single failure outside of design basis.
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2-50-445(446)/9712-01 VIO Five examples of a 10 CFR Part 50, Apper. dix 8, Criterion XVI Corrective Action Violation.
50-445/9712-02 VIO Failure to contain reference to previous similar events in licenseo event report.
50-445(446)/97 !2-03 IFl Shelf life of actuator diaphragms.
50-445(446)/9712-05 VIO Procedures failed to provide adequate instruction for the material to use to attach lead shielding.
50-445/9802-03 URI Inadvertent removal of source range detector during maintenance.
50-445/9805-01 NCV Inadvertent removal of source range detector during maintenance.
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